Not applicable.
1. Field of the Invention
The present invention generally relates to an apparatus and method for characterizing multiphase oil well effluents, typically comprising water, crude oil and gas, using measurements associated with the fluid mixture. More particularly, the present invention relates to an apparatus for measuring multiple energy gamma ray attenuations through the effluent mixture and a method for determining the effluent phase volume fractions of water, oil and gas from these measurements. Still more particularly, a preferred embodiment of the present invention relates to an apparatus and method for determining effluent phase volume fractions for an inhomogeneous flow condition using the gamma ray attenuation measurements.
2. Background of the Invention
Advances in petroleum drilling and production technology make it possible to economically explore and produce oil and gas in areas that were previously inaccessible, such as deepwater offshore fields. New technologies also provide opportunities to maximize oil and gas recoveries from existing offshore and onshore reservoirs. Producing these fields economically requires optimized production methods, improved production allocations, enhanced reservoir management, and accurate pipeline measurement. To accomplish these objectives, producers and pipeline operators must determine, as accurately as possible, oil well effluent characteristics.
Oil well effluents are multiphase fluids typically comprising water, oil and gas phases. Total mixture flow rate, component phase flow rates, and effluent composition (i.e. the phase volume fractions of water, oil and gas) are all important to producers and pipeline operators. By evaluating these characteristics, a producer can take corrective action when necessary to optimize production operations over the life of the field and thereby enhance reservoir management. Once an oil well effluent is produced, it is typically transported through pipelines to treating facilities. Knowledge of oil well characteristics is also critical in pipeline measurement applications for leak detection and custody transfer measurement purposes.
In practice, developing a method for accurately determining oil well effluent characteristics has been challenging due to the multiphase nature of the fluid and its varying flow conditions. As effluent is produced or transported, it is exposed to changing pressures, temperatures and pipe configurations that create inhomogeneous, unstable, and unpredictable flow patterns in the multiphase fluid. An especially problematic flow condition is the slug flow regime where phase stratification occurs causing the gas to come out of solution and form pockets apart from the liquid phase. As the effluent moves in the slug flow regime, gas and liquid sections alternate at varying frequencies, thereby affecting the accuracy of standard liquid flow meters designed to perform in single-phase liquids. The industry refers to the gas and liquid sections as either gas xe2x80x9cslugsxe2x80x9d and liquid xe2x80x9cplugsxe2x80x9d or gas xe2x80x9cfilmsxe2x80x9d and liquid xe2x80x9cslugs.xe2x80x9d The former xe2x80x9cslug and plugxe2x80x9d industry nomenclature will be used herein.
The traditional oil industry practice for determining effluent characteristics has been to periodically divert the well output to a test separator to split the effluent into its component phases. Once the phases are separated, they are then measured independently using conventional orifice, positive displacement, or turbine meter devices as appropriate for the phase being measured. This operation has several inherent limitations. Separators are physically large, costly, and particularly ill-suited for use offshore where platform space is scarce and enlarging the platform can significantly increase capital costs. From a measurement standpoint, it is often impractical for each well to have a dedicated separator so several wells typically share a common separator making continuous well effluent monitoring impossible. Additionally, stabilized well flow is necessary for accurate measurement, and testing the effluent from just one well can take up to a whole day.
Over the past twenty years, various devices and techniques have been proposed for on-line multiphase fluid measurements that eliminate the need for separators. Most suggest a combination of measurement sensors for separately determining total flow rate and volume fractions of one or more of the phases.
U.S. Pat. No. 4,144,754, incorporated by reference herein for all purposes, describes one of the first multiphase meters. The apparatus comprises a flow loop and a gamma ray densitometer. The flow loop exerts centrifugal force on the fluid mixture that generates differential pressure on the fluid between the inner and outer walls of the loop. The densitometer measures the fluid mixture density. By correlating the differential pressure and density the total mixture flow rate can be determined. Wile this meter is applicable for fluids of unknown or varying density, it does not seem to accurately account for the xe2x80x9cslipxe2x80x9d phenomenon that occurs when the gas phase flow rate differs from the mixture flow rate. To resolve this problem, mixing devices may be added upstream of the flow meter to homogenize the flow and equalize flow velocities; however this solution adds to the capital costs and increases the required space for the measurement equipment.
U.S. Pat. No. 4,282,760, incorporated herein for all purposes, describes a method for improved measurement accuracy that accounts for the slip phenomenon and determines liquid (oil and water) and gas mass flow rates. The method makes use of multiple densitometers to measure mixture, liquid and gas densities and correlate those measurements with differential pressure to determine total, liquid and gas phase mass flow rates. Although improving measurement accuracy, more equipment is required, thereby adding to the complexity and cost.
Since the early days of multiphase measurement, numerous methods for accomplishing accurate measurement have been proposed, including capacitance techniques, reflection or scatter techniques, and transmission techniques based on measurements of neutrons, infrared, ultrasonics, microwaves, or gamma rays. U.S. Pat. No. 5,591,922, incorporated herein for all purposes, describes a method and apparatus for determining multiphase effluent phase proportions and mass flow rates for the mixture and for each component phase. The apparatus comprises a Venturi and a device for measuring gamma ray or X-ray attenuation at three different energy levels correlating with and proportional to each effluent phase to be measured. A low absorption window may be incorporated into the Venturi section of the pipeline to increase the transmission of radiation through the crude oil, and a gas-charged, proportional counter tube detector is used to measure gamma ray attenuation.
Several advances and improvements have been made over the basic Venturi and gamma ray source/detector apparatus and method. PCT Application EP94/01320, the contents of which are incorporated by reference for all purposes, discloses an improvement to the apparatus gamma ray window by employing a lining of carbon fiber reinforced resin (CFRE) within the meter conduit. The lining forms a window with the advantages of low radiation absorption while allowing relatively high internal pressures to be applied.
European Patent Specification EP 0,696,354 B1, the contents of which are incorporated by reference for all purposes, discloses an improvement to the gamma ray detector design by employing a dual area solid-state semiconductor diode detector for improved measurement accuracy in detecting both low and high-energy emission lines. Since detector efficiency is significantly lower at high-energy emission lines, the efficiency of the detector is improved by providing a solid state detector configuration with at least two radiation detecting surfaces. A filter is located between the radiation source and the first detecting surface to prevent the low energy radiation from passing through to that detecting surface. In this manner, one detecting surface is specifically employed to measure high-energy emission lines and the other detecting surface measures low energy emission lines. The resolution and efficiency of this detector configuration is further improved by providing a suitable cooling means forming a Peltier element to maintain the detector temperature at 0-15 degrees Celsius. EP 0,696,354 B1 and PCT Application EP94/01320 each disclose a method of acquiring measurements at five low energy gamma ray energy emission lines using Americium-241 to improve measurement accuracy. Having more than two energy emission lines can improve measurement accuracy by comparing effluent composition determinations at various energy levels and applying a least squares fit. Additionally, U.S. Pat. No. 5,854,820, incorporated by reference herein for all purposes, discloses a method for determining produced water salinity by using a third energy emission line in addition to the minimum two energy emission lines required to determine phase volume fractions. Compensation for variations in produced water salinity can improve the accuracy of phase volume fraction calculations and reduce meter calibration requirements.
Gamma ray, X-ray and other transmission techniques are generally considered superior to reflection or scatter techniques for determining fluid volumes across the pipe. Transmission techniques are therefore preferred for accurate flow rate determinations in homogeneous fluid mixtures of oil, water and gas. One shortcoming, however, is the requirement of a long radiation path length in liquid to obtain adequate sensitivity for determining volume and mass fractions. These transmission techniques can therefore be inadequate for inhomogeneous flow regimes such as stratified flow or slug flow where liquid plugs and gas slugs alternate frequently and measurements taken during a gas slug will introduce measurement inaccuracies.
To overcome this difficulty, several approaches have been suggested for determining effluent characteristics under inhomogeneous flow conditions. U.S. Pat. No. 5,654,551, incorporated by reference herein for all purposes, discloses a method for measuring phase mass flow rates using several gamma ray source/detector devices. Gamma ray attenuation measurements are taken in the traditional way while one source/detector device is used solely to detect the beginning and ending of each gas slug or liquid plug. This method of compensation seems to be directed only at correcting for inhomogeneous flow in the slug flow regime and would appear to be inadequate for measurements in another type of inhomogeneous flow such as stratified flow.
Similarly, PCT Application EP98/05239, the contents of which are incorporated by reference for all purposes, discloses a method for measurement compensation particularly directed at the slug flow regime where measurements are acquired at high frequencies compared to the gas/liquid alternation cycle and these measurements are averaged over a time corresponding to a low frequency compared to the gas/liquid alternation cycle. The averaged values are used in calculations to determine effluent characteristics. This method uses a confidence coefficient, determined as a function of density, that is applied to weight the water to liquid ratio calculated for each high frequency sample.
Even with these substantial advances in multiphase metering, however, substantial problems still exist. For example, the accuracy of multiphase measurement for determining phase volume fractions remains undesirably low for inhomogeneous flow regimes. In light of the significant volumes of effluent produced, these errors can seriously and negatively impact production operations, lead to inefficient reservoir management and generate substantial financial miscalculations between a buyer and seller of the hydrocarbon stream. Thus, it would be desirable to develop an apparatus or method to provide accurate, timely measurement data for key parameters of the effluent stream resulting in efficient well management and production optimization.
Ideally, this method or apparatus would overcome limitations of earlier compensation methods for improving the accuracy of phase fraction determinations for all types of inhomogeneous flow, not just for the slug flow regime. The preferred embodiment of the present invention provides a solution to this limitation by applying a correction factor to convert an inhomogeneous gamma ray count rate to an effective homogeneous gamma ray count rate, thereby making the homogeneous flow equations applicable for determining phase volume fractions.
The present invention relates to an apparatus and method for determining the phase volume fractions for a multiphase oil well effluent, typically comprising water, crude oil and gas. More particularly, the present invention relates to an apparatus for measuring multiple energy gamma ray attenuations through the effluent mixture and a method for determining the effluent phase volume fractions of water, oil and gas from these measurements when the mixture is under inhomogeneous flow conditions.
The apparatus comprises a pipe section including a converging Venturi. The Venturi induces a pressure drop as the mixture flows through the pipe section. The preferred embodiment includes a removable central Venturi nose cone, which allows the meter flow rate range to be modified in situ by exchanging the central Venturi nose cone.
A radiation source produces radioactive rays (i.e. gamma or X-rays) at two or more energy levels that pass through the mixture perpendicular to the flow stream. These radioactive rays are attenuated to varying degrees, depending upon their energies and on the fractions of water, oil and gas present. One exemplary embodiment of the present invention utilizes an Americium-241 radioactive gamma ray source.
A solid state detector measures the transmitted gamma ray count rates at each energy level. In the exemplary embodiment, the solid state detector comprises two or more radiation detecting surfaces and a filter preventing certain of the energy levels from passing through to the detecting surface. The preferred detector also includes a suitable cooling means, such a Peltier element, which enhances the resolution and allows the detector to distinguish between the closely spaced low-energy lines from the radioactive source.
A section or window formed of a low radiation absorption material such as, for example, Carbon Fiber Reinforced Epoxy (CFRE) or boron carbide, is preferably incorporated in the area of the detector in lieu of the pipe wall to increase the transmission of radiation to the detector. The preferred window configuration is a specially designed truncated cone shape that optimizes the window strength, allowing it to withstand high internal pressures, while also lowering absorption of radiation through the window as compared to prior art configurations.
The method comprises measuring the gamma-ray attenuation, in the two-energy example, at one high-energy emission line (E1), to help differentiate between the liquid and gas components, and at one low-energy emission line (E2), to help differentiate between the water and oil phases. To correct for the distorting effects of inhomogeneous flow, the attenuation count-rates at E1 are measured over short time intervals compared to the measurement period for E2.
The attenuation count rates for E1 are used to estimate the gas/liquid distribution over the measurement period by calculating a liquid fraction. An important parameter required in determining the gas/liquid distribution is the water-cut, w, of the liquid phase. As this is not known a priori, a best estimate is entered into the liquid fraction calculation.
Using the calculated liquid fraction, theoretical inhomogeneous and homogeneous count rates for each energy level are calculated. Correction factors, based on the theoretical homogeneous/inhomogeneous count-rate ratios, are then applied to the total measured count rates at each energy level to yield corrected (i.e. equivalent homogeneous) total count-rates. These corrected total count-rates may then be entered into homogeneous flow equations to yield estimates of the phase volume fractions and a better estimate for the water-cut. The entire calculation is iterated until no further improvement is gained in the derived phase fractions.